Three-stage process for deasphalting resid, removing fines from decanted oil and apparatus therefor

ABSTRACT

The invention reduces cracking catalyst fines in decanted oil by mixing the decanted oil (DCO) containing cracking catalyst fines with asphaltene and then treating the DCO-asphaltene mixture with a non-aromatic hydrocarbon solvent in an extraction unit or in a multi-stage deasphalting unit.

CROSS-REFERENCE TO RELATED APPLICATION

The present invention is a continuation-in-part of copending application Ser. No. 07/381,372 filed July. 18, 1989 now U.S. Pat. No. 5,013,427.

BACKGROUND OF THE INVENTION

The present invention relates to an improved process for deasphalting resid and substantially removing cracking catalyst fines from decanted oil.

Catalytic cracking of oil is an important refinery process which is used to produce gasoline and other hydrocarbons. During catalytic cracking, the feedstock, which is generally a cut or fraction of crude oil, is cracked in a reactor under catalytic cracking temperatures and pressures in the presence of a catalyst to produce more valuable, lower molecular weight hydrocarbons. Gas oil is usually used as a feedstock in catalytic cracking. Gas oil feedstocks typically have a boiling range from 650° F. to 1000° F. and less than 1% RAMS carbon by weight. Gas oil feedstocks also typically contain less than 5% by volume naphtha and lighter hydrocarbons having a boiling temperature below 430° F., from 10% to 30% by volume diesel and kerosene having a boiling range from 430° F. to 650° F., and less than 10% by volume resid having a boiling temperature above 1000° F. It is desirable to provide an effective process to increase the yield of gasoline (naphtha) in catalytic cracking units.

It has been known to deasphalt and catalytically crack virgin unhydrotreated, low sulfur resid as well as to deasphalt, subsequently hydrotreat, and catalytically crack high sulfur resid. However, better demetalization and higher resid conversion are desirable.

Furthermore, such prior art processes produce hydrogen-rich asphaltenes which are difficult and expensive to handle and process, melt (liquify) at relatively low temperatures, and which cannot be used as solid fuel. Asphaltenes are difficult to blend into fuel oils, and are not generally usable and desirable for asphalt paving or for use in other products.

In the past, spiraling oil costs and extensive price fluctuations have created instability and uncertainty for net oil consuming countries, such as the U.S. It has been difficult to attain adequate supplies of high-quality, low-sulfur, petroleum crude oil (sweet crude) from Nigeria, Norway, and other countries at reasonable prices for conversion into gasoline, fuel oil, and petrochemical feedstocks. In an effort to stabilize the supply and availability of crude oil at reasonable prices, Amoco Oil Company has developed, constructed, and commercialized extensive, multimillion dollar refinery projects under the Second Crude Replacement Program (CRP II) to process poorer quality, high-sulfur, petroleum crude oil (sour crude) and demetalate, desulfurize, and hydrocrack resid to produce high value products, such as gasoline, distillates, catalytic cracker feed, metallurgical coke, and petrochemical feed-stocks. The Crude Replacement Program is of great benefit to the oil-consuming nations since it provides for the availability of adequate supplies of gasoline and other petroleum products a reasonable prices while protecting the downstream operations of refining companies.

During resid hydrotreating, such as under Amoco Oil Company's Crude Replacement Program, resid oil is upgraded with hydrogen and a hydrotreating catalyst to produce more valuable lower-boiling liquid products. However, undesirable carbonaceous solids are formed during resid hydrotreating. These solids have been characterized as multicondensed aromatics which form and precipitate from cracking of the side chains of asphaltenes. These carbonaceous solids ar substantially insoluble in hexane, pentane, and in the effluent hydrotreated product oil. The solids become entrained and are carried away with the product. Such solids tend to stick together, adhere to the sides of vessels, grow bigger, and agglomerate. Such solids are more polar and less soluble in other hydrocarbons than the residual oil feedstock. Carbonaceous solids are produced as a reaction by-product during ebullated bed hydrotreating (expanded bed hydrotreating). During ebullated bed hydrotreating, the ebullating hydrotreating catalyst fines can serve as a nucleus and center for asphaltene growth. The situation becomes even more aggravated when two or more hydrotreating reactors are connected in series as in many commercial operations. In such cases, solids formed in the first reactor not only form nucleation sites for solids growth and agglomeration in the first reactor, but are carried over with the hydrotreated product oil into the second reactor, etc., for even larger solids growth and agglomeration.

The concentration of carbonaceous solids increases at more severe hydrotreating conditions, at higher temperatures and at higher resid conversion levels. The amount of carbonaceous solids is dependent on the type of feed. Operability at high resid conversion is limited by the formation of carbonaceous solids.

Solids formed during resid hydrotreating cause deposition and poor flow patterns in the reactors, as well as fouling, plugging, and blocking of conduits and downstream equipment. Oils laden with solids cannot be efficiently or readily pipelined. Hydrotreating solids can foul valves and other equipment, and can build up insulative layers on heat exchange surfaces reducing their efficiency. Buildup of hydrotreated solids can lead to equipment repair, shutdown, extended downtime, reduced process yield, decreased efficiency, and undesired coke formation.

Decanted oil (DCO) is a valuable solvent and is used advantageously in the resid hydrotreating unit for controlling the carbonaceous solids therein. However, decanted oil is normally obtained from a catalytic cracking unit and contains cracking catalyst solids or fines therein. These fines are small particles made up of the catalyst used in the catalytic cracking unit.

For a fluid catalytic cracking unit, the preferred cracking catalysts are those containing crystalline aluminosilicates, zeolites, or molecular sieves in an amount sufficient to materially increase the cracking activity of the catalyst, e.g., between about 1 and about 25% by weight. The crystalline aluminosilicates can have silica-to-alumina mole ratios of at least about 2:1, such as from about 2 to 12:1, preferably about 4 to 6:1 for best results. The crystalline aluminosilicates are usually available or made in sodium form. This component is preferably reduced, for instance, to less than about 4 or even less than about 1% by weight through exchange with hydrogen ions, hydrogen-precursors such as ammonium ions, or polyvalent metal ions.

Suitable polyvalent metals include calcium, strontium, barium, and the rare earth metals such as cerium, lanthanum, neodymium, and/or naturally-occurring mixtures of the rare earth metals. Such crystalline materials are able to maintain their pore structure under the high temperature conditions of catalyst manufacture, hydrocarbon processing, and catalyst regeneration. The crystalline aluminosilicates often have a uniform pore structure of exceedingly small size with the cross-sectional diameter of the pores being in a size range of about 6 to 20 angstroms, preferably about 10 to 15 angstroms.

Silica-alumina based cracking catalysts having a significant proportion of silica, e.g., about 40 to 90 weight percent silica and about 10 to 60 weight percent alumina, are suitable for admixture with the crystalline aluminosilicate or for use as such as the cracking catalyst.

The decanted oil cracking catalyst fines are more abrasive than resid hydrotreating unit (RHU) fines. The cracking catalyst fines in decanted oil are abrasive and have a tendency to put undue wear on the valves and various feed and product controls used to convey the decanted oil during its use as a solvent.

Our U.S. Pat. No. 4,940,529 teaches a solvent extraction deasphalting unit for hydrotreated resid from vacuum tower bottoms. The solvent extraction unit comprises a mixer and two or three separator vessels or zones operated slightly below or above the critical conditions of the solvent.

Our U.S. Pat. No. 4,808,298 is directed to resid hydrotreating and to a minimization of the formation of carbonaceous solids from hydrotreating. Pat. No. 4,808,298 does this by treating the resid oil feedstock or hydrotreated oil with an aromatic diluent such as decanted oil obtained from the decanted oil line of a fluid catalytic cracker unit. The process illustrated in U.S. Pat. No. 4,808,298 injects the decanted oil diluent into the atmospheric tower and the vacuum tower.

Over the years a variety of processes and equipment have been suggested for refining operations. Typifying some of those prior art processes and equipment are those described in U.S. Pat. Nos:

    ______________________________________                                         2,360,272                                                                               3,635,815     4,305,814                                                                               4,502,944                                      2,382,382                                                                               3,661,800     4,331,533                                                                               4,521,295                                      2,398,739                                                                               3,681,231     4,332,674                                                                               4,525,267                                      2,398,759                                                                               3,766,055     4,341,623                                                                               4,526,676                                      2,414,002                                                                               3,796,653     4,341,660                                                                               4,592,827                                      2,425,849                                                                               3,838,036     4,381,987                                                                               4,606,809                                      2,436,927                                                                               3,844,973     4,391,700                                                                               4,617,175                                      2,755,229                                                                               3,905,892     4,400,264                                                                               4,618,412                                      2,879,224                                                                               3,909,392     4,405,441                                                                               4,622,210                                      2,884,303                                                                               3,923,636     4,434,045                                                                               4,640,762                                      2,981,676                                                                               3,948,756     4,439,309                                                                               4,655,903                                      2,985,584                                                                               4,040,958     4,446,002                                                                               4,661,265                                      3,004,926                                                                               4,082,648     4,447,313                                                                               4,662,669                                      3,039,953                                                                               4,137,149     4,451,354                                                                               4,673,485                                      3,168,459                                                                               4,158,622     4,454,023                                                                               4,681,674                                      3,338,818                                                                               4,176,048     4,457,830                                                                               4,686,028                                      3,351,548                                                                               4,191,636     4,457,831                                                                               4,692,318                                      3,364,136                                                                               4,239,616     4,478,705                                                                               4,695,370                                      3,513,087                                                                               4,285,804     4,485,004                                                                               4,720,337                                      3,563,911                                                                               4,290,880     4,486,295                                                                               4,743,356                                      3,579,436                                                                               4,302,323     4,495,060                                                                               4,753,721                                      4,767,521                                                                               4,769,127     4,773,986                                                                               4,808,289                                                                      4,818,371                                      ______________________________________                                    

It is, therefore, desirable to provide an improved process for substantially reducing the amount of cracking catalyst fines in decanted oil and to provide an improved process for deasphalting resid.

DEFINITIONS

The term "asphaltenes" as used herein, means asphaltenes which have been separated and obtained from a deasphalting unit. Asphaltenes comprise a heavy polar fraction. The asphaltene fraction is the residue which remains after the resins and oils have been separated from resid in a deasphalting unit. Asphaltenes from vacuum resid are generally characterized as follows: a Conradson or Ramsbottom carbon residue of 30 to 90 weight % and a hydrogen to carbon (H/C) atomic ratio of 0.5% to less than 1.2%. Asphaltenes can contain from 50 ppm to 5000 ppm vanadium and from 20 ppm to 2000 ppm nickel. The sulfur concentration of asphaltenes can be from 110% to 250% greater than the concentration of sulfur in the resid feed oil to the deasphalter. The nitrogen concentration of asphaltenes can be from 110% to 350% greater than the concentration of nitrogen in the resid feed oil to the deasphalter.

As used herein, the terms "deasphalting unit" and "deasphalter" mean one or more vessels or other equipment which are used to separate asphaltenes from oils and resins.

The term "fine-lean DCO", or "fine-free DCO" as used herein, means decanted oil having less than 20 ppm silica and less than 20 ppm alumina.

The term "low sulfur" resid as used herein means a resid comprising less than 2% by weight sulfur. Resid containing sulfur, other than low sulfur resid, is sometimes characterized as high sulfur resid.

The term "resins" as used herein, means resins that have been separated and obtained from a deasphalting unit. Resins are denser or heavier than deasphalted oil and comprise more aromatic hydrocarbons with highly aliphatic substituted side chains. Resins, which also comprise metals, such as nickel and vanadium. Resins from vacuum resid can be generally characterized as follows: a Conradson or Ramsbottom carbon residue of 10 to less than 30 weight % and a hydrogen to carbon (H/C) atomic ratio of 1.2% to less than 1.5%. Resins can contain 1000 ppm or less of vanadium and 300 ppm or less of nickel. The sulfur concentration in resins can be from 50% to 200% of the concentration of sulfur in the resid oil feed to the deasphalter. The nitrogen concentration in resins can be from 30% to 250% of the concentration of nitrogen in the resid oil feed in the deasphalter.

The terms "resid oil" and "resid" as used herein, mean residual oil.

The term "solvent-extracted oil" (SEU oil) as used herein, means substantially deasphalted, substantially deresined oil which has been separated and obtained from a solvent extraction unit.

The term "solvent extraction unit" (SEU) as used herein, means a deasphalter in which resid is separated into deasphalted oil, resins, and asphaltenes by means of one or more solvents.

The term "supercritical conditions" as used herein, means a condition in a deasphalting unit where the solvent does not exist in both a vapor phase and a liquid phase. Under such circumstances, the solvent is generally in a gaseous or vapor phase.

SUMMARY OF THE INVENTION

In keeping with one aspect of the invention, we provide an improved process for deasphalting resid and for reducing fines in decanted oil. W mix decanted oil containing cracking catalyst fines with the resid to form a DCO-resid mixture. Then we treat the DCO resid mixture with a solvent extraction unit or a three-stage deasphalting unit.

The resid may be the heavy fraction product from a resid hydrotreating unit (RHU), a hydrotreated resid from vacuum tower bottoms (RHU-VTB), atmospheric tower bottom resid, a low sulfur resid (LSR) or a high sulfur resid. In many instances, a high sulfur crude is fed to a hydrotreating unit or a plurality of hydrotreating units. The resids from the resid hydrotreating units (RHU) can be further fractionated in a fractionator such as in an atmospheric tower and/or vacuum tower, leaving resid bottoms.

The resid bottoms which are mixed with the DCO containing catalytic fines are further separated into separate streams of resins, asphaltenes, and fine-lean DCO-oil mixture in a deasphalting unit, preferably a three-stage solvent extraction unit operated with supercritical solvent recovery. The deasphalted, solvent-extracted DCO-oil mixture is preferably recycled to the ebullated bed reactor of the resid hydrotreating unit a part of the feedstock. The asphaltenes can be transported for use as solid fuel. Some of the asphaltenes can also be fed to the coker and coked, or passed to a calciner for subsequent use as coke in a metal processing mill.

The asphaltenes which have been hydrotreated and separated in a deasphalter, preferably a solvent extraction unit, in contrast to virgin asphaltenes, have relatively low sulfur, typically less than 3.5% by weight, and can be used directly as solid fuel.

Hydrotreated deasphalted oils generally contain low concentrations of RAMS carbon (ramsbottom carbon), sulfur, and metals, and are especially useful as catalytic cracker feed. It is unexpected to be able to isolate a large fraction (about 40-70 wt%) of deasphalted oil from the vacuum bottoms effluent that has low RAMS carbon, because hydrotreating generally causes the RAMS carbon in the vacuum bottoms to increase about 50% or more relative to the virgin unhydrotreated vacuum residue. Also, it was surprisingly found that the increase in RAMS carbon in the hydrotreated vacuum bottoms is due to a selective increase in the concentration of RAMS carbon in the asphaltene fraction, while the RAMS carbon content of the deasphalted oils and resins ar relatively unchanged compared to virgin unhydrotreated resid.

More than 95% by weight of the metals in the vacuum bottoms were removed from the deasphalted oil during solvent extraction. These peculiar findings make the deasphalting of hydrotreated vacuum bottoms a particularly attractive alternative to direct delayed coking in that the asphaltene fraction is so refractory and of such a low reactivity as to produce such a small oil yield that it is economically used as a solid fuel. The deasphalted oil and/or resins have substantially no silica fines (less than 20 ppm). Thus, DCO recovered from the fractionators has substantially no cracking catalyst fines and can be advantageously used as a solvent to control the formation of carbonaceous solids in the hydrotreating unit. Furthermore, the hydrotreated resins fraction is comparable in reactivity t virgin resid and converts efficiently and effectively into lighter products upon recycle to the resid hydrotreating unit.

The method of our invention qenerally uses a resid selected from hydrotreated resid, low sulfur resid (LSR), high sulfur resid, and preferably vacuum tower bottoms from a resid hydrotreating unit. The solvent used for the solvent extraction is selected from non-aromatic hydrocarbon solvents having 3 to 7 carbon atoms and mixtures of the solvents. The preferred solvents are butane, pentane, isomers thereof and mixtures thereof.

We provide three solvent separators operated near or above critical conditions wherein the resid, decanted oil (DCO) containing cracking catalyst fines and hydrocarbon solvent are fed to a first separator. In this regard, preferably the resid and DCO are first mixed with each other and then mixed with the solvent. Preferably the major portion of the solvent or all of the solvent is added directly to the first extractor.

Optionally when RHU-VTB or a similar type of resid is used, a LSR may be used along with the DCO.

The first separator separates a substantial amount of the cracking catalyst fines from the DCO and a substantial amount of the metals from the resid. The metals and fines are wet and held by the asphaltene phase formed in the first separator. The asphaltene phase is removed from th first separator as a solvent-extracted deresined asphaltene.

Also extracted from the first separator is a mixture of DCO from which the cracking catalyst fines have been substantially removed (containing less than 20 ppm silica and less than 20 ppm alumina), resin, oil and solvent (fine-lean DCO-resin-oil-solvent mixture). The fine-lean DCO-resin-oil-solvent mixture is conveyed to a second separator unit.

From the second separator unit there is extracted and recovered substantially deasphalted resin. Also extracted is the fine-lean DCO-oil-solvent mixture which is conveyed to the third separator unit. From the third separator unit, fine-lean DCO-oil mixture and solvent are separated and recovered. The solvent is recycled to the first separator and/or resid-DCO mixture.

In the above three stage deasphalting unit, LSR may be added to either or both the feeds to the first extractor and second extractor.

The fine-lean DCO is a valuable product which can be upgraded in various processes since DCO is reactive toward hydrogenation. Further, the fine-free DCO is a good solvent and as stated above, aids in controlling the carbonaceous solids formed in a resid hydrotreating unit.

A more detailed explanation is provided in the following description and appended claims taken in conjunction with the accompanying drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic flow diagram of a refinery in accordance with principles of the present invention;

FIG. 2 is a schematic flow diagram for partially refining crude oil;

FIG. 3 is a schematic flow diagram of a three stage solvent extraction unit.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT

In refining (FIG. 2), unrefined, raw, whole crude oil (petroleum) is withdrawn from an above ground storage tank 10 at about 75° F. to about 80° F. by a pump 12 and pumped through feed line 14 into one or more desalters 16 to remove particulates, such as sand, salt, and metals, from the oil. The desalted oil is fed through furnace inlet line 18 into a pipestill furnace 20 where it is heated to a temperature, such as to 750° F. at a pressure ranging from 125 to 200 psi. The heated oil is removed from the furnace through exit line 22 by a pump 24 and pumped through a feed line 25 to a primary distillation tower 26.

The heated oil enters the flash zone of the primary atmospheric distillation tower, pipestill, or crude oil unit 26 before proceeding to its upper rectifier section or the lower stripper section. The primary tower is preferably operated at a pressure less than 60 psi. In the primary tower, the heated oil is separated into fractions of wet gas, light naphtha, intermediate naphtha, heavy naphtha, kerosene, virgin gas oil, and primary reduced crude. A portion of the wet gas, naphtha, and kerosene is preferably refluxed (recycled) back to the primary tower to enhance fractionation efficiency.

Wet gas is withdrawn from the primary tower 26 through overhead wet ga line 28. Light naphtha is removed from the primary tower through light naphtha line 29. Intermediate naphtha is removed from the primary tower through intermediate naphtha line 30. Heavy naphtha is withdrawn from the primary tower 26 through heavy naphtha line 31. Kerosene and oil for producing jet fuel and furnace oil are removed from the primary tower through kerosene line 32. Primary virgin, atmospheric gas oil is removed from the primary tower through primary gas oil line 33 and pumped to the fluid catalytic cracking unit (FCCU) 34 (FIG. 1).

Primary reduced crude is discharged from the bottom of the primary tower 26 (FIG. 2) through the primary reduced crude line 35. The primary reduced crude in line 35 is pumped by pump 36 into a furnace 38 where it is heated, such as to a temperature from about 520° F. to about 750° F. The heated primary reduced crude is conveyed through furnace discharge line 40 into the flash zone of a pipestill vacuum tower 42.

The pipestill vacuum tower 42 is preferably operated at a pressure ranging from 35 to 50 mm of mercury. Steam is injected into the bottom portion of the vacuum tower through steam line 44. In the vacuum tower, wet gas is withdrawn from the top of the tower through overhead wet gas line 46. Heavy and/or light vacuum gas oil are removed from the middle portion of the vacuum tower through heavy gas oil line 48. Vacuum-reduced crude is removed from the bottom of the vacuum tower through vacuum-reduced crude line 50. The vacuum-reduced crude typically has an initial boiling point near about 1000°. The vacuum-reduced crude, also referred to as resid, resid oil, and virgin unhydrotreated resid, is pumped through vacuum-reduced crude lines 50 and 52 by a pump 54 into a feed drum or surge drum 56. Resid oil is pumped from the surge drum through resid feed line 58 (FIG. 1) into a resid hydrotreating unit complex 60 (RHU) which has a plurality of resid hydrotreating units and associated refining equipment.

Each resid hydrotreating unit can be a reactor train comprising a cascaded series or set of ebullated bed reactors. Hydrogen is injected into the ebullated bed reactors and a relatively high sulfur resid or sour crude is fed to the reactor where it is hydroprocessed (hydrotreated) in the presence of ebullated (expanded) fresh and/or equilibrium hydrotreating catalyst and hydrogen to produce an upgraded effluent product stream with reactor tail gas (effluent off gases, leaving used spent catalyst. Hydroprocessing in the RHU includes demetallation, desulfurization, denitrogenation, resid conversion, oxygen removal (deoxygenation), hydrocracking, removal of Rams carbon, and the saturation of olefinic and aromatic hydrocarbons.

Each of the reactor trains has plurality of reactors in series, i.e. ebullated bed reactors. The oil feed is typically resid oil (resid) and heavy gas oil. The feed gas comprises upgraded recycle gases and fresh makeup gases. Demetallation primarily occurs in the first ebullated bed reactor in each train. Desulfurization occurs throughout the ebullated bed reactors in each train. The effluent product stream typically comprises light hydrocarbon gases, hydrotreated naphtha, distillates, light and heavy gas oil, and unconverted hydrotreated resid. The hydrotreating catalyst typically comprises a metal hydrogenating component dispersed on a porous refractory, inorganic oxide support.

The resid hydrotreating unit is quite flexible and, if desired, the same catalyst can be fed to one or more of the reactors; or, a separate demetallation catalyst can be fed to the first reactor while a different catalyst can be fed to the second and/or third reactors. Alternatively, different catalysts can be fed to each of the reactors, if desired. The used and spent catalyst typically contains nickel, sulfur, vanadium, and carbon (coke). Many tons of catalyst are transported into, out of, and replaced in the ebullated bed reactors daily.

Although we have just described the use of ebullated bed reactors, fixed bed reactors may also be used. The ebullated bed reactors are preferred.

As shown in FIG. 1, the products produced from the resid hydrotreating units in the ebullated bed reactors include: light hydrocarbon gases (RHU gases) in gas line 62; naphtha comprising light naphtha, intermediate naphtha, heavy naphtha and vacuum naphtha in one or more naphtha lines 64; distillate comprising light distillate and mid-distillate in one or more distillate lines 66; light gas oil in gas oil line 68; light vacuum gas oil and heavy vacuum gas oil in one or more vacuum gas oil lines 70; and hydrotreated vacuum resid comprising vacuum tower bottoms in a vacuum resid line 72.

Light and intermediate naphthas can be sent to a vapor recovery unit for use as gasoline blending stocks and reformer feed. Heavy naphtha can be sent to the reformer to produce gasoline. The mid-distillate oil is useful for producing diesel fuel and furnace oil, as well as for conveying and/or cooling the spent catalyst.

Resid hydrotreated (RHU) light gas oil is useful as feedstock for the catalytic cracking unit 34. Light and heavy vacuum gas oils can be upgraded in a catalytic feed hydrotreating unit 74 (CFHU). Some of the hydrotreated resid from vacuum tower bottoms (RHUVTB) can be sent to the coker unit 76 via coker inlet line 78 to produce coke. A substantial portion of the RHU-VTB is fed through a feeder line or inlet line 80 to a deasphalter, deasphalting unit or sovent extraction unit (SEU) 88 where the RHU-VTB is separated into deasphalted oil, resins, and asphaltenes.

Decanted oil (DCO) with cracker catalys fines is fed through feeder line 116 to the SEU 88.

In one embodiment, the deasphalter 88 (FIG. 1) comprises a solvent extraction unit operated with supercritical solvent recovery. A mixture of deasphalted solvent-extracted oil and fine-lean DCO in DCO-oil line 91 is useful as part of the feed to resid hydrotreating unit (RHU) 60. This increases the yield of more valuable lower-boiling liquid hydrocarbons, controls the carbonaceous solids and eliminates cracking catalyst fines in the RHU. A mixture of deasphalted SEU oil in DCO-oil line 90 is useful as part of the feedstock to the catalytic cracking unit 34 to increase the yield of gasoline and other hydrocarbon liquids. Deasphalted solvent-extracted resins (SEU resins) in SEU resin line 92 are useful as part of the feed to the RHU 60 to increase the yield of more valuable lower-boiling liquid hydrocarbons.

A portion of the asphaltenes can be conveyed or passed through an asphaltene line or chute 94 or otherwise transported to solid fuels mixing and storage facility 96, such as a tank, bin or furnace, for use as solid fuel. Another portion of the solvent-extracted asphaltenes (SEU asphaltenes) can be conveyed or passed through a SEU asphaltene line or chute 98 to the coker 76.

The effluent product streams discharged from the reactors comprise hydrotreated resid oil and reactor tail gas (effluent off gases) The tail gas comprises hydrogen, hydrogen sulfide, ammonia, water, methane, and other light hydrocarbon gases, such as ethane, propane, butane and pentane.

Heavy coker gas oil from line 100 (FIG. 1), and/or heavy vacuum gas oil (HVGO) from the heavy vacuum gas oil lines 48 (FIG. 2) and possibly solvent extracted oil 90 (FIG. 1) are conveyed into an optional catalytic feed hydrotreater or catalytic feed hydrotreating unit (CFHU) 74 (FIG. 1). There, it is hydrotreated with hydrogen from hydrogen feed line 102 at a pressure ranging from atmospheric pressure to 2000 psia, preferably from 1000 psia to 1800 psia at a temperature ranging from 650° F. to 750° F. in the presence of a hydrotreating catalyst. The hydrotreated gas oil is discharged through a catalytic feed hydrotreater discharge line 104.

Light atmospheric ga oil in RHU LGO line 68 and/or primary gas oil in line 33 from the primary tower 26 (pipestill) can also be fed and conveyed into the catalytic cracking reactor 34. Kerosene can be withdrawn from the catalytic feed hydrotreating unit 74 (FIG. 1) through CFHU kerosene line 106.

Suitable cracking catalyst for the FCCU 34 include, but are not limited to, those catalysts which contain silica and/or alumina, especially the acidic type. The cracking catalyst may contain other refractory metal oxides such as magnesia or zirconia. The catalyst was described above in more detail.

Naphtha is withdrawn from the FCCU 34 through a naphtha line 108. LCCO is withdrawn from the FCCU through a light catalytic cycle oil line 110. HCCO is withdrawn from the FCCU product fractionation section through a heavy catalytic cycle oil line 112. Decanted oil is withdrawn from the bottom of the FCCU through a decanted oil line 114. The DCO contains fine particles of the catalyst (fines). These particles are detrimental to processing equipment. These particles are very difficult to remove by conventional processes such as filtering and centrifuging.

Our invention removes these particles by treating the DCO from the FCCU with resid. The DCO containing cracking catalyst fines can be fed to the SEU 88 via DCO feed line 116. In the SEU 88, the DCO is mixed with resid and/or solvent before being subjected to the solvent recovery steps.

As shown in FIG. 1, resid (i.e., RHU-VTB) in RHU-VTB line 78 is fed into the coker (coking vessel) 76. Solvent-extracted asphaltenes in the SE asphaltene line 118 can also be conveyed to the coker 76. In the coker 76, resids and solvent-extracted asphaltenes are coked at a coking temperature of about 895° F. to about 915° F. at a pressure of about 10 psig to about 50 psig. Coke is withdrawn from the coker 76 through chute, conduit, or line 120 and transported to a coke storage area for use as solid fuel.

In the coker tower 76, the coker product can be separated into fractions of coker gas, coker naphtha, light coker gas oil (LCGO), and heavy coker gas oil (HCG0). Coker gas can be withdrawn from the coker through coker gas line 122. Coker naphtha can be withdrawn through coker naphtha line 124. Light coker gas oil can be withdrawn through light coker gas line 126. Heavy coker gas oil can be withdrawn through heavy coker gas oil line 100 and hydrotreated in the catalytic feed hydrotreater (CFHU) 74 before being catalytically cracked in the catalytic cracker 34 (FCCU).

The critical temperatures and pressures for the solvents generally used in this invention are as follows:

    ______________________________________                                                       T(°F.)                                                                        P (psi)                                                    ______________________________________                                         butane          307     530                                                    pentane         387     484                                                    hexane          455     435                                                    heptane         512     395                                                    ______________________________________                                    

In FIG. 3, the solvent extraction deasphalting unit 88 comprises a mixer 128 and three separator vessels or zones 130, 132 and 134, which are operated slightly below or above the critical condition of the solvent. Resid hydrotreated vacuum tower bottoms (i.e., hydrotreated resid from the vacuum tower) in RHU VTB line 80 is conveyed to the mixer, mixing vessel, or mixing zone 128.

For best results, the solvent comprises substantially pentane and/or butane and/or isomers. The ratio of total solvent (fresh and recycle solvent) to feed (vacuum towe bottoms-DCO mixture) is from about 3:1 to about 20:1 and preferably from about 8:1 to about 12:1 for best results. In some circumstances it may be desirable to use or include other solvents.

Decanted oil (DCO) containing cracking catalyst fines is mixed with the resid in mixer 128. The ratio of decanted oil to resid is from about 1:5 to about 3:2 and preferably from about 1:3 to about 3:2.

The resid is a resid wherein a substantial portion of the resid boils above about 850° F. and preferably above about 1000° F.

The decanted oil is a DCO wherein a substantial portion of the DCO boils above about 850° F. and preferably above about 500° F.

In the preferred embodiment, a minority of fresh makeup solvent in fresh solvent line 136 is pumped through a combined solvent line 138 and into the mixer 128. A minority of recycled solvent in recycle solvent line 141 is also pumped through the combined solvent line 138 and into the mixer 128. Most of the fresh and recycled solvent is added directly to the first separator 130, via solvent feed line 139. This is added at the bottom portion of the separator 130 countercurrently to the vacuum tower bottoms, in order to obtain countercurrent extraction of the asphaltenes in the first separator 130.

The ratio of total solvent (fresh and recycle solvent) to feed (DCO-resid mixture) is from about 3:1 to about 20:1 and preferably from about 8:1 to about 12:1 for best results. In some circumstances it may be desirable to use or include other solvents.

The resid (RHU-VTB), DCO with fines and solvent are mixed in the mixer 128 and conveyed through a DCO-resid-solvent line 140 to the first separator vessel or zone 130. In some circumstances, it may be desirable that the decanted oil and the vacuum tower bottoms and solvent be fed directly into the first separator 130 in the above ratios without previously mixing the decanted oil and vacuum tower bottoms and solvent.

In the first separator (asphaltene separator) 130, there is formed an SEU asphaltene phase. The SEU asphaltene phase wets and therefore holds all of the catalyst fines. The asphaltene phase is separated from the mixture of decanted oil, solvent and hydrotreated resid (vacuum tower bottoms). A substantial amount of the SEU asphaltenes are withdrawn from the first separator 130 through SEU asphaltene line 94 and, following solvent recovery, conveyed or otherwise transported to a solids fuel area 96 (FIG. 1) for use as solid fuel. Some of the solvent-extracted asphaltenes are withdrawn from the first separator and conveyed or otherwise transported through SEU asphaltene line, conduit, or chute 118 to the coker unit 76 or blend to No. 6 oil.

The first separator can be operated at a temperature from about 150° F. to near the critical temperature of the solvent and a pressure at least equal to the vapor pressure of the solvent when at a temperature below the critical temperature of the solvent and at least equal to the critical pressure of the solvent when at a temperature equal to or above the critical temperature of the solvent. Preferably, the operating temperature of the first separator 130 ranges from about 20° F. below the critical temperature of the solvent to about the critical temperature of the solvent. The operating pressure of the first separator 130 is substantially the same as the pressure of the third separator 134, plus the pressure drops between the vessels 130 and 134.

The majority of the solvent and the remaining fine-lean decanted oil, resins and oil components of the hydrotreated resid are withdrawn from the first separator 130 and conveyed through DCO-resin-oil-solvent line 142 and a heater or heat exchanger to the second separator vessel or zone 132. The second separator 132 is maintained at a temperature level higher than the temperature level in the first separator 130 and at the same pressure as the first vessel 130 minus any pressure drops between vessels 130 and 132. This effects a separation of the influent residue into a fluid-like light phase comprising fine-lean decanted oil, oils and solvent and a fluid-like heavy phase comprising resins and a minority of the DCO and solvent. The second light phase which separates within second separator 132 collects in an upper portion of the second separator 132.

In the second separator (resin separator) 132, deasphalted resins are separated from the influent. The solvent-extracted deasphalted resins are discharged from the second separator 132 through an SEU resin line 92 and fed to the ebullated bed reactor of the resid hydrotreating unit as part of the feed as discussed previously.

If desired, some of the resins can be recycled to the second separator 132 through a recycle resin line 133 The recycled resins contacts the second light phase of oil and solvent and thereafter settles through the second light phase. This reflux action improves the efficacy of the separation occurring in the second separator 132, which tends to concentrate Ramsbottom carbon residue and metals in the resins fraction. The recycled resins can be passed into the upper portion of second separator 132 through a nozzle or other suitable device which disperses the second heavy phase of resins as substantially uniform droplets. The droplets are of sufficient size to facilitate their settling through the rising second light phase comprising a portion of the fine-lean decanted oil, oils and solvent. The second separator 132 can contain a packaging material, such as Demister packing, Pall rings, Raschig rings or the like.

Preferably, the operating temperature of the second separator 132 is from about 5° F. to about 100° F. above the temperature in the first separator 130, and most preferably at a temperature of from about 5° F. to about 50° F. above the critical temperature of the solvent, and the operating pressure of the second separator 132 is substantially the same pressure level as is maintained in first separation zon 130.

The remaining fine-lean decanted oil, solvent and oil are withdrawn from the second separator 132 through DCO-solvent-oil line 144 and passed via a heater or heat exchanger to the third separator vessel or zone 134. In the third separator (oil separator) 134 substantially deasphalted demetallized resin-free (deresined) oil and fine-lean decanted oil are separated from the solvent. The third separator 134 is operated at an elevated temperature to effect a separation of the fine-lean DCO-oil mixture and solvent. The temperature in the third separator 134 is higher than the temperature in the second separator 132 and above the critical temperature of the solvent. The pressure in the third separator 134 is preferably at least equal to the critical pressure of the solvent. Preferably, the temperature in the third separator 134 is maintained at least about 50° F. above the critical temperature of the solvent.

The third separator 134 acts as a flash zone in which solvent is separated from the oil. When operating at supercritical conditions, no heat of vaporization is required to separate the solvent from the fine-lean DCO-oil thereby enhancing the energy efficacy of the deasphalter.

The solvent is withdrawn from the third separator 134 (FIG. 3) and recycled through lines 138, 139 and 141 into the mixer 128 and/or first separator 130. The solvent-extracted oil and fine-lean decanted oil mixture (fine-lean DCO-oil mixture) are discharged from the third separator 134 through DCO-oil line 146.

The fine-lean DCO-oil mixture can be used as is and fed to the ebullated bed reactor or fed to a distillation unit wherein the fine-lean DCO is separated from the fine-lean DCO-oil mixture and th SEU oil can then be fed directly to the FCCU via line 90.

In the above apparatus, the first, second and third heavy phases of asphaltenes, resins, and DCO-SEU oil, respectively, can be passed into individual stripping sections, such as steam strippers, to strip any solvent that may be contained in the phases. The recovered solvent can be recycled (pumped) through line 141. The recovered solvent can optionally be passed through a cooler, heater, or other heat exchanger as well as a surge drum before being pumped through the recycle line 141.

LSR may be added to the mixer 128 via LSR feed line 148 and/or to the DCO-resin-oil-solvent feed line 142 via LSR feed line 150. The LSR may be added to a separate mixer to be mixed with the fine-free DCO-resin-oil-solvent mixture or alternatively directly to the second separator 132.

It was unexpectedly and surprisingly found that decanted oil containing cracking catalyst fines ca be substantially cleaned of their fines by mixing the decanted oil with a resid and subjecting the mixture to a solvent extraction process.

Further, it was unexpected and surprisingly found that mixing decanted oil with a hydrotreated vacuum tower bottom resid and subjecting these to multi-stage solvent extraction increases the recovery of valuable products and reduces the yield of asphaltenes compared to deasphalting the feeds separately.

The following Examples 1 and 2 were run using a three-stage deasphalting unit and Examples 3 and 4 were run using a two-stage deasphalting unit. The results for the three-stage deasphalting unit of the present invention would be equivalent with regard to the amount of catalyst fines removed from the DCO and the yield of asphaltene.

EXAMPLE 1

Vacuum-reduced crude (resid oil) was hydrotreated in a resid hydrotreating unit similar to that shown in FIGS. 1 and 2 and then in a three stage or three separator deasphalter and under operating conditions similar to that described previously in this specification with regard to the separators except that no decanted oil or low sulphur resid was added. The vacuum tower bottoms (hydrotreated resid) were separated by solvent extraction into fractions of asphaltenes, (deasphalted) resins and (deasphalted) deresined SEU oil. The composition of the hydrotreated resid, asphaltenes, resins, and SEU oil are shown in Table 1.

                                      TABLE 1                                      __________________________________________________________________________                               FEED                                                                           Sum of                                                           Oil Resin                                                                              Asphaltene                                                                           Products                                                                            Measured                                        __________________________________________________________________________     Yield, Wt % 40  36  24    --   --                                              Carbon, Wt %                                                                               87.08                                                                              87.18                                                                              88.78 87.52                                                                               87.53                                           Hydrogen, Wt %                                                                             10.77                                                                              10.29                                                                              6.40  9.55 9.38                                            Sulfur, Wt %                                                                               1.45                                                                               1.73                                                                               4.10  2.19 2.16                                            Nitrogen, Wt %                                                                             0.41                                                                               0.49                                                                               1.26  0.64 0.61                                            Nickel, ppm 0.9 2.8 169   42   39                                              Vanadium, ppm                                                                              1.0 3.1 354   86   76                                              Iron, ppm   0.6 0.6 43    11   6                                               H/C, Atomic 1.47                                                                               1.41                                                                               0.86  1.30 1.28                                            RAMS carbon, Wt %                                                                          8.2 14.4                                                                               70.4  25.4 26.6                                            CCR, Wt %   10.3                                                                               13.8                                                                               71.5  26.6 26.7                                            API         14.1                                                                               7.9 (-24.5)                                                                              (2.6)                                                                               2.6                                             % C.sub.A   33.8                                                                               38.3                                                                               73.9  45.0 44.8                                            1000-, Wt % 25  11  --    14   18                                              Ring and Ball, °F.                                                                  112 95  377   --   112                                             Viscosity @ 210 F., cSt                                                                    70  128 --    --   764                                             Viscosity @ 275 F., cSt                                                                    20  31  --    --   101                                             C.sub.5 Insoluble, Wt %                                                                    2.3 3.6 96.5  25.9 24.3                                            C.sub.7  Insoluble, Wt %                                                                   1.9 2.5 93.7  24.7 16.5                                            __________________________________________________________________________

EXAMPLE 2

The same RHU-VTB resid of Example 1 was deasphalted under operating conditions similar to that described in Example 1. However, in this example we use DCO which contains a cracking catalytic fines and wherein a substantial portion of the DCO boils above about 850° F. This is added to the mixer, Properties of the products obtained are presented in Table 2.

                                      TABLE 2                                      __________________________________________________________________________                               FEED                                                                           Sum of                                                           Oil Resin                                                                              Asphaltene                                                                           Products                                                                            Measured                                        __________________________________________________________________________     Yield, Wt % 64  11  25    --   --                                              Carbon, Wt %                                                                               87.86                                                                              87.95                                                                              89.21 88.21                                                                               88.12                                           Hydrogen, Wt %                                                                             10.19                                                                              9.33                                                                               6.17  9.09 9.05                                            Sulfur, Wt %                                                                               1.52                                                                               1.85                                                                               3.78  2.12 1.83                                            Nitrogen, Wt %                                                                             0.36                                                                               0.46                                                                               0.98  0.53 0.53                                            Nickel, ppm 0   0   161   40   41                                              Vanadium, ppm                                                                              0   4   393   99   108                                             Iron, ppm   0   0   73    18   22                                              H/C, Atomic 1.38                                                                               1.26                                                                               0.82  1.23 1.22                                            RAMS carbon, Wt %                                                                          7.9 18.2                                                                               67.3  24.0 26.0                                            CCR, Wt %   9.8 18.5                                                                               67.5  25.2 25.3                                            API         8.6 3.3 (-18.4)                                                                              (1.2)                                                                               (1.2)                                           Ring and Ball, °F.                                                                  127 116 361   --   110                                             Viscosity @ 210 F., cSt                                                                    63  271 --    --   591                                             Viscosity @ 275* F., cSt                                                                   18  47  --    --   80                                              C.sub.5 Insoluble, Wt %                                                                    1.6 5.9 86.6  23.3 20.5                                            C.sub.7 Insoluble, Wt %                                                                    0.6 3.5 80.5  20.9 15.8                                            __________________________________________________________________________

EXAMPLE 3

The efficiency of our method for removing catalyst fines is shown by Example 3.

RHU-VTB and DCO having a substantial portion boiling above about 850° F. was treated with a two stage solvent extraction deasphalter. The solvent used was pentane and the conditions were the same as Example 2.

The recovered asphaltene and DCO-oil-resin mixture were measured to determine the amount of silica and alumina which were removed from the feed.

                                      TABLE 3                                      __________________________________________________________________________     SILICA AND ALUMINA CONTENT                                                     FOR PRODUCTS FROM RHU-VTB/DCO 850+                                                           Silica     Alumina                                                             (as Oxide) (as Oxide)                                                                % of        % of                                                         SiO.sub.2 ppm                                                                        Total                                                                               Al.sub.2 O.sub.3 ppm                                                                  Total                                          __________________________________________________________________________     Feed (Avg of 4 Tests)                                                                        323 ± 16                                                                          --   478 ± 34                                                                           --                                             Asphaltene (Avg of 5 Tests)                                                                  800 ± 280                                                                         62 ± 22                                                                          1032 ± 282                                                                         54 ± 15                                     Oils/Resins (Avg of 2 Tests)                                                                 9 ± 4                                                                             2 ± 1                                                                            0.5 ± 0.1                                                                           0.1 ± 0.02                                 __________________________________________________________________________

As Table 3 illustrates, the silica content in oils/resin stream is less than 9±4 ppm when the starting compound had 323±16 ppm silica and the alumina content in the oils/resins was 0.6±0.1 ppm when the starting compound had 478±34 ppm alumina.

EXAMPLE 4

2,579 lbs. (6 drums) of RHU-VTB and 1,551 lbs. (4 drums of DCO) from Texas City #3 FCU was blended in a mixing kettle. The DCO has a substantial portion boiling above about 500° F.

A portion of the above feed was treated by the two separator process set out above. The deasphalted oil (DAO) was analyzed as well as the asphaltene obtained from the first separator. The DAO comprises a DCO-resin-oil mixture.

An average yield for this run of 10.5 wt% asphaltene and 89.5 wt% deasphalted oil (DAO).

The presence of the decanted oil caused a beneficial reduction in the asphaltene yield. The RHU-VTB used in this test had a slightly lower RAMS carbon content than the RHU-VTB used in previous tests (22.5 wt% vs. 26.6 wt%). Therefore, the asphaltene yield is expected to be slightly lower. Based on previous results for hydrocracked resids, the anticipated RHU-VTB asphaltene yield is 19 wt% (vs. 24 wt% in the previous tests). The present test with mixed feed actually yielded 10.5 wt% asphaltene overall, or 16.8 wt% on RHU-VTB (assuming no asphaltenes from decanted oil). If we conservatively assume that the decanted oil yielded 3% asphaltenes then the actual incremental asphaltene yield of the RHU-VTB is 15.0 wt%, 20% lower than the value expected in the absence of a co-solvent effect.

Table 4 presents inspections of a sample of the asphaltenes produced by this example. The properties are similar in most respects to those measured on asphaltenes from RHU vacuum tower bottoms (VTB) without decante oil present except for lower sulfur content (which reflects lower sulfur in the RHU-VTB used as feed) and a slightly lower H/C (0.82 vs. 0.86). The lower H/C shows that the asphaltenes being rejected are more aromatic and less desirable as a hydrotreater feed stock.

                  TABLE 4                                                          ______________________________________                                                       Asphaltene                                                                     Sample                                                           ______________________________________                                         Carbon, wt %    89.63                                                          Hydrogen, wt %  6.15                                                           Sulfur, wt %    2.05                                                           Nitrogen, wt %  0.97                                                           H/C             0.82                                                           Rams, wt %      71.4                                                           % C.sub.a (NMR) 77.4                                                           Oxide Ash, wt % 0.8                                                            Moisture, wt %  0.1                                                            % volatiles, wt %                                                                              55.2                                                           ______________________________________                                    

Referring to Table 5, the presence of the decanted oil significantly alters the DAO properties relative to DAO from RHU-VTB alone. As expected, decanted oil results in a decrease in nitrogen, H/C, RAMS carbon, and API gravity. It increased the aromatically, yielding a better solvent for control of carbonaceous solids in the RHU.

                  TABLE 5                                                          ______________________________________                                         DAO PROPERTIES                                                                 ______________________________________                                         Carbon, wt %         88.52                                                     Hydrogen, wt %       9.42                                                      Sulfur, wt %         1.42                                                      Nitrogen, wt %       0.34                                                      Ni, ppm             <2                                                         V, ppm              <2                                                         Fe, ppm             <2                                                         H/C                  1.28                                                      RAMScarbon           7.83                                                      % C.sub.a (NMR)      50.3                                                      API                  5.7                                                       Oils                 32.7                                                      Resin                66.9                                                      Asphaltenes          0.4                                                       Viscosity            22.92 CST @ 100° C.                                Viscosity            8.35 CST @ 135° C.                                 ______________________________________                                    

The yields and qualities of the deasphalted SEU oil, resins, and asphaltenes vary considerably with the solvent used in deasphalting and the deasphalting conditions. However, the property ranges given for deasphalted SEU oil, deasphalted resins, and deresined asphaltenes are appropriate for a broad range of process conditions in the use of deasphalters.

It is understood that the qualities of the deasphalted oil, deasphalted resin, and deresined asphaltene fractions can be adjusted somewhat by altering processing conditions in the deasphalter. This adjustment is analogous to raising or lowering the cut points on a distillation tower in order to obtain the product qualities desired.

Although embodiments of this invention have been shown and described, it is to be understood that various modification and substitutions, as well as rearrangements and combinations of process steps and equipment, can be made by those skilled in the art without departing from the novel spirit and scope of this invention. Therefore, the following claims are to be construed to include all equivalent structures, methods and processes. 

We claim:
 1. A method of deasphalting a hydrotreated resid and substantially removing cracking catalyst fines from decanted oil containing cracking catalyst fines comprising:feeding to a first separator hydrotreated resid, decanted oil containing cracking catalyst fines and a non-aromatic hydrocarbon solvent, said non-aromatic hydrocarbon solvent being selected from the group consisting of non-aromatic hydrocarbon solvents having 3-7 carbon atoms and mixtures thereof, treating the hydrotreated resid, decanted oil containing cracking catalyst fines and the non-aromatic hydrocarbon solvent in said first separator to separate therein substantially deresined asphaltene having substantially all of the cracking catalyst fines and a substantially deasphalted fine-lean decanted oil-resin-oil-solvent mixture, recovering substantially deresined asphaltenes containing said cracking catalyst fines from said first separator, recovering substantially deasphalted fine-lean decanted oil-resin-oil solvent mixture from said first separator, feeding the substantially deasphalted fine-lean decanted oil-resin-oil-solvent mixture from said first separator to a second separator, separating in said second separator substantially deasphalted resins and a substantially deasphalted fine-lean decanted oil-oil-solvent mixture, recovering substantially deasphalted resins from said second separator, recovering substantially deasphalted fine-lean decanted oil-oil-solvent mixture from said second separator, feeding said substantially deasphalted fine-lean decanted oil-oil-solvent mixture from said second separator to a third separator, separating in said third separator a solvent and a substantially fine-lean and substantially deasphalted oil mixture from said third separator, recovering a substantially fine-lean and substantially deasphalted oil-decanted oil mixture from said third separator, recovering solvent from said third separator, and recycling at least a portion of said solvent from said third separator to said first separator.
 2. The method of claim 1 comprising mixing low sulphur resid with said feeds to and/or from said first separator.
 3. The method of claim 2 wherein the solvent is selected from the group consisting of butane, pentane, isomers thereof and mixtures thereof.
 4. A method of claim 2 wherein the resid is a vacuum tower bottom resid derived from a hydrotreating unit.
 5. The method of claim 4 wherein solvent is mixed with the decanted oil and resid prior to being fed to the first separator and also said solvent is added directly to said first separator.
 6. The method of claim 4 wherein a substance portion of the decanted oil boils above about 850° F.
 7. The method of claim 4 wherein a substantial portion of the decanted oil boils above about 500° F.
 8. The method of claim 1 wherein the resid is a vacuum tower bottom resid derived from a hydrotreating unit obtained from high sulfur crude and the solvent is selected from the group consisting of butane, pentane, isomers thereof and mixtures thereof.
 9. The method of claim 8 wherein at least a portion of the solvent and a portion of solvent recovered from the third separator are added directly to the fist separator.
 10. A hydrotreating process comprising the steps of,hydrotreating a resid with hydrogen in the presence of a hydrotreating catalyst to produce a hydrotreated resid containing hydrotreating catalyst fines; solvent extracting in a first stage of a three-stage solvent extraction unit, a fraction of the hydrotreated resid with a decanted oil containing cracking catalyst fines and a first non-aromatic hydrocarbon solvent selected from the group consisting of hydrocarbon solvents having 3-7 carbon atoms and mixtures thereof, recovering substantially deresined asphaltenes containing a substantial amount of said cracking catalyst fines from said first sage, recovering substantially deasphalted fine-lean decanted oil-resin-nil-solvent mixture from said first stage, feeding the substantially deasphalted fine-lean decanted oil-resin-oil-solvent mixture from said fist stage to a second stage, recovering substantially deasphalted resins from said second stage, recovering substantially fine-lean and substantially deasphalted decanted oil-oil-solvent mixture from said second stage, feeding said substantially fine-lean and substantially deasphalted decanted oil-oil-sovent mixture from said second stage to a third stage, recovering a substantially fine-lean and substantially deasphalted oil-decanted oil mixture from said third stage, recovering solvent from said third stage, recycling at least a portion of said solvent from said third stage to said first stage, and hydrocracking said deasphalted oil-decanted oil mixture in a hydrotreating unit with hydrogen in the presence of a hydrogenation catalyst to produce upgraded oil.
 11. The process of claim 10 comprisingrecovering substantially deasphalted decanted oil-resin-oil-solvent mixture containing less than 20 ppm silica and less than 20 ppm alumina from said first stage, recovering a substantially deasphalted resins having less than 20 ppm silica and less than 20 ppm alumina from said second stage, and recovering a substantially deasphalted oil-decanted oil mixture having less than 20 ppm silica and less than 20 ppm alumina fromsaid third stage.
 12. The process of claim 11 wherein the resid being hydrotreated is selected from the group consisting of high sulfur resid, low sulfur resid and mixtures thereof.
 13. The process of claim 11 wherein a substantial portion the decanted oil boils above about 850° F.
 14. The process of claim 11 wherein a substantial portion of the decanted oil boils above about 500° F.
 15. The process of claim 12 wherein the resid is a high sulfur crude and the solvent is selected from the group consisting of butane, pentane, isomers thereof and mixtures thereof.
 16. The process of claim 11 wherein the solvent is selected from the group consisting of butane, pentane, isomers thereof and mixtures thereof, maintaining the temperature in the first separator from about 20° F. below the critical temperature of the solvent to near the critical temperature of the solvent.
 17. The process of claim 16 wherein a substantial portion of the decanted oil boils above 850° F.
 18. A hydrotreating process, comprising the steps of,substantially desolating crude oil; heating said desalted crude oil in a pipestill furnace; pumping said heated crude oil to a primary distillation tower; separating said head crude oil in said primary distillation tower into stream of naphtha, kerosene, primary gas oil, and primary reduced crude oil; pumping said primary reduced crude oil to a pipestill vacuum tower; separating said primary reduced crude in said pipestill vacuum tower into stream of wet gas, heavy gas oil, and vacuum reduced crude oil providing resid oil; feeding a composite feed comprising solvent extracted substantially deasphalted resins, a substantially catalyst fine-lean and substantially deasphalted oil-decanted oil mixture, and said resid oil from said pipestill vacuum tower to a resid hydrotreating unit comprising a series of ebullated bed reactors; injecting hydrogen-rich gases into said ebullated bed reactors; conveying resid hydrotreating catalysts to said ebullated bed reactors; ebullating said composite feed with said hydrogen-rich gases the presence of said resid hydrotreating catalyst in said ebullated bed reactors under hydrotreating conditions to produce upgraded hydrotreated resid oil containing hydrotreating catalyst fines; separating said upgraded hydrotreated resid oil into vacuum tower bottoms comprising vacuum resid oil containing hydrotreating catalyst fines; mixing at least a portion of said vacuum tower bottoms with a decanted oil containing cracking catalyst fines; treating in a first stage of a three-stage solvent extraction unit at least a portion of said vacuum tower bottoms and said decanted oil containing cracking catalyst fines with a non-aromatic hydrocarbon solvent being selected from the group consisting of non-aromatic hydrocarbon solvents having 3-7 carbon atoms and mixtures thereof; recovering from said first stage a catalyst laden stream of asphaltene comprising substantially deresined asphaltenes and a substantial amount of said hydrotreating catalyst fines and cracking catalyst fines; recovering a subsonically fine-lean and substantially deasphalted decanted oil-resin-oil-solvent mixture form said first stage having a substantially smaller concentration of catalyst fines than were in said first stage; feeding the substantially fine-lean and substantially deasphalted decanted oil-resin-oil-solvent mixture to a second stage of said three-stage solvent extraction unit; recovering substantially deasphalted resins from said second stage; recovering substantially fine-lean and substantially deasphalted decanted oil-oil-solvent mixture from said second stage;, feeding said substantially fine-lean decanted oil-oil-solvent mixture from said second stage to a third stage; recovering a substntially fine-lean and substantially deasphalted oil-decanted oil mixture from said third stage, recovering solvent from said third stage; recycling at least a portion of said solvent from said third stage to said first stage, and recycling at least one of said substantially deasphalted resins from said second stage, and said substantially fine-lean and substantially deasphalted oil-decanted oil mixture from said third stage to said bed reactors as pat of said composite feed.
 19. The process of claim 18 comprising, maintaining a temperature of said first stage from about 20° F. below the critical temperature of the solvent to near the critical temperature of the solvent, and,recovering from said first stage a substantially deresined asphaltene wherein said asphaltene contains a substantial amount of said catalyst fines.
 20. The process of claim 19 comprising recovering a substantially deasphalted decanted oil-resin-oil-solvent mixture containing less than about 20 ppm silica and less than about 20 ppm alumina from said first stage,recovering a substantially deasphalted resin stream having less than about 20 ppm silica and less than about 20 ppm alumina from said second stage, recovering a substantially deasphalted oil-decanted oil mixture having less than about 20 ppm silica and less than about 20 ppm alumina, from said third stage, and recovering solvent from said third stage. 